Crude oil production from subterranean reservoirs may involve use of various flooding methods as the natural forces that are used in the “primary recovery” process become depleted. A large portion of the crude oil may have to be driven out of the formation in “secondary” or “tertiary” recovery processes. In addition, some reservoirs may not have sufficient natural forces for oil production even by primary recovery processes. Enhanced oil recovery methods are one example of such recovery processes used to improve the production of crude oil.
Currently, the petroleum industry is re-evaluating technologies that will improve the ability to recover remaining and untapped oil from the subterranean reservoirs. Injecting a displacing fluid or gas may begin early, long before the complete depletion of the field by primary recovery processes. Methods for improving displacement efficiency or sweep efficiency may be used at the very beginning of the first injection of a displacing fluid or gas, rather than under secondary and tertiary recovery conditions.
The easiest method of flooding a subterranean reservoir for the production of crude oil is by injecting a liquid or a gas into the well to force the oil to the surface. Water flooding is the most widely used fluid. However, water does not readily displace oil because of the high interfacial tension between the two liquids, which results in high capillary pressure that traps the oil in porous media.
The addition of chemicals to the flooding liquid has been used to modify early flooding techniques in order to improve the oil recovery. Surfactants are one class of chemical compounds that have been used in aqueous media for enhanced oil recovery. Surfactants have been found to effectively lower the interfacial tension between oil and water and enable mobilization of trapped oil through the reservoir.
Surfactants have been used in flooding operations, alone, or in conjunction with secondary surfactants or co-surfactants and/or sacrificial agents. Surfactants, such as alkylaryl sulfonates, are able to lower the interfacial tension between oil and water, and when used in conjunction with appropriate amounts of other inorganic salts, such as, sodium chloride or sodium carbonate, they exhibit desirable phase behavior. Depending on the molecular weight and molecular weight distribution, branching and point of attachment of the aryl group to the alkyl groups, alkylaryl sulfonates can be tailored to preferentially reside in the aqueous or oleic phases at different electrolyte concentrations (salinities). At low salinities the alkylaryl sulfonates reside in water and at high salinities they partition into the oil. In either case, the swollen micellar solutions that contain surfactants, oil, and water are termed microemulsions. At “optimal salinity” an equal volume of oil and water are solubilized in the microemulsion. For well tailored and matched surfactants, the high volumes of oil and water solubilized in the microemulsion result in ultra-low interfacial tensions that provide potential for high oil recovery from reservoirs.
The salinity of the water in subterranean hydrocarbon reservoirs may vary a great deal. For example, the Minas oil field in Indonesia has total dissolved salts of between 0.2 and 0.3 weight percent. Other reservoirs may have salinities as high as or higher than 20.0 percent sodium chloride and over 0.5 percent calcium chloride and magnesium chloride. It is desirable to optimize the surfactant for enhanced oil recovery for a particular reservoir by evaluating tailored versions of the surfactants with native reservoir brine and reservoir oil under subterranean reservoir conditions via phase behavior experiments. In addition to the phase behavior experiments, interfacial tension measurements can be taken, such as by using a spinning drop tensiometer, to verify that the interfacial tensions are acceptably low. In addition to testing the surfactants in the laboratory, additional field or pilot tests with injected solutions can be performed as in some instances the injectate brine is different from native reservoir brines.
Surfactants can be optimized by adjusting the molecular weight and/or molecular weight distribution of the surfactant to maximize the amount of oil in the aforementioned microemulsion. Other components may also be used in combination with the surfactant, such as inorganic alkaline salts, co-solvents, polymeric materials, and co-surfactants to improve phase behavior. The performance of an enhanced oil recovery formulation may also be measured by the oil solubilization parameter, which is the volume of oil dissolved per unit volume of surfactant. The square of oil solubilization value is inversely proportional to interfacial tension. In addition, the performance can also be measured by the ability of the formulation to achieve stable microemulsions and low interfacial tensions rapidly, such as in less than one day in the laboratory.
In the past, minimal attention has been paid to aqueous stability. During the London floods, another operator achieved aqueous stability of the surfactant-polymer formulation, but did not consider the interactions with the chase solutions. Similarly, during the surfactant field trial in Minas in 2002, there was not an importance placed upon aqueous stability, which was a contributing factor to lower than anticipated oil recovery.
A number of published reports have discussed methods for enhanced oil recovery using flooding with anionic surfactant systems. These systems depend on ion exchange to shift the salinity/ionic strength to a region of optimal oil recovery potential. These systems are marginally phase-stable or unstable mixtures after (or even before) injection into the formation and produce less than optimum oil recovery. Some systems use solvents such as alcohols or miscible solvents that help keep the components as a single phase. Others have incorporated an oil in the surface mixture that is higher in molecular weight than the oil that is meant to be recovered from the formation. This approach forms a micro-emulsion and a less than optimum mixture at surface conditions. In addition to the phase stability problems associated with anionic surfactant systems, the costs of the systems are often not economically viable due to the high chemical costs.
There is limited research on the use of non-ionic surfactants in enhanced oil recovery operations, and actual attempts to use non-ionic surfactants in such operations have failed to produce successful results. For example, non-ionic surfactants have been used as the main component in a surfactant flood, but have not shown to improve recovery. See e.g. “Potential Use of Non-ionic Surfactants in Micellar Flooding,” L. A. Verkruyse and S. J. Salter, Int'l Symposium on Oilfield and Geothermal Chemistry (SPE 13574), 9-11 Apr. 1985, Phoenix, Ariz., USA (1985).